Quantitative assessment of well leakage, part II: Case studies for CCS

Abstract

This paper presents the second part of a two-part series on estimating fluid migration along wells. We use the results of the model described in the first paper and outline a leakage calculation methodology. The present method considers the mechanical behaviour of the flow pathway, formation creep, visco-inertial effects, and the operational conditions of the well to provide a deterministic evaluation of fluid migration along the well. Two case studies are presented that focus on a CO2 injection well in a depleted reservoir and a legacy well in an aquifer CCS project. The results indicate that there is a pressure threshold below which CO2 may not flow through the cemented annulus. Beyond that point, the flow rate increases non-linearly with storage pressure. The size of the leakage pathway changes over time with the pressure and temperature of the system and is not a static parameter. Visco-inertial effects and creep could reduce the potential leak rate. The computed rates should be considered as an upper bound in this work as the impact of multiphase flow was not considered. This type of assessment is critical to conduct quantitative risk assessments for CCS projects. The results enable operators to manage storage pressure, reduce the cost of MMV (Measurement, Monitoring, and Verification) plans, and improve well designs. We argue that the impact of the magnitude of leakage rates reported in this work should be weighed against the improvements to the economics of CCS projects with an increased pressure/storage capacity.